Oil companies' conduct seismic surveying to lower risk and to reduce costs of locating and developing new oil and gas reserves. Seismic surveying is, therefore, an up front cost with intangible return value. Consequently minimizing the cost of seismic surveying and getting quality results in minimum time are important aspects of the seismic surveying process.
Seismic surveys are conducted by deploying a large array of seismic sensors over a surface portion of the earth. Typically, these arrays cover 50 square miles and may include 2000 to 5000 seismic sensors. An energy source (buried dynamite for example) is discharged within the array and the resulting shock wave is an acoustic wave that propagates through the subsurface structures of the earth. A portion of the wave is reflected at underground discontinuities, such as oil and gas reservoirs. These reflections are then sensed at the surface by the sensor array and recorded. Such sensing and recording are referred to herein as seismic data acquisition, which might also be performed in a passive mode without an active seismic energy source.
A three dimensional map, or seismic image, of the subsurface structures is generated by moving the energy source to different locations while collecting data within the array. This map is then used to make decisions about drilling locations, reservoir size and pay zone depth.
A very important factor in determining the quality and resolution of the seismic image is the density of sensors in the array. Those skilled in the art recognize that greater sensor density, i.e., number of sensors in the array, provides sharper and clearer images.
The density of sensors is usually limited by economic and reliability factors. If the cost can be lowered and reliability increased, higher quality seismic images can be acquired. Better image quality can enable better informed drilling decisions and thus reduce investment risk for the oil company.
The traditional sensor has long been a geophone velocity measuring sensor. Today, accelerometers are becoming more widely utilized, and multi-axis, or multi-component, accelerometers are emerging. Multi-component (three axis) sensing has shown to give superior images of the subsurface as compared to single component sensing. Multi-component sensing, however, has not been economically viable in the past due to the added cost of the recording system and implementation problems with multi-component analog sensors. With the advent of the multi-component digital sensor, such as the Vectorseis® sensor module available from ION Geophysical Corporation, Houston, Tex., a multi-component digital sensor is now practical. Multi-component recording, however, requires higher sensor density than single component recording to realize the full advantage seismic imaging with multi-component recording.
The most popular architecture of current seismic data acquisition systems is a point-to-point cable connection of all of the sensors. Output signals from the sensors are usually digitized and relayed down the cable lines to a high-speed backbone field processing device or field box. The high-speed backbone is typically connected in a point-to-point relay fashion with other field boxes and then to a central recording system where all of the data are recorded onto magnetic tape.
Seismic data may be recorded at the field boxes for later retrieval, and in some cases a leading field box will communicate command and control information with the central recorder over a radio link. Still, there exists miles of cabling between the individual field boxes, between the field boxes and sensor lines, and between the sensors.
The above cable system architecture results in more than 100 miles of cable deployed over the survey area. The deployment of miles of cable over varying terrain requires significant equipment and labor, often in environmentally sensitive areas.
FIG. 1 depicts a typical seismic data acquisition system 100. The typical system 100 includes an array (“string”) of spaced-apart seismic sensor units 102. Each string of sensors is typically coupled via cabling to a data acquisition device (“field box”) 103, and several data acquisition devices and associated string of sensors are coupled via cabling 110 to form a line 108, which is then coupled via cabling 110 to a line tap or (“crossline unit”) 104. Several crossline units and associated lines are usually coupled together and then to a central controller 106 housing a main recorder (not shown). The typical sensor unit 102 in use today is a velocity geophone used to measure acoustic wave velocity traveling in the earth. Recently, and as noted above, acceleration sensors (accelerometers) are finding more widespread acceptance for measuring acceleration associated with the acoustic wave. Each sensor unit might comprise a single sensor element or more than one sensor element for multi-component seismic sensor units.
The sensors 102 are usually spaced at least on the order of tens of meters, e.g., 13.8-220.0 feet. Each of the crossline units 104 typically performs some signal processing and then stores the processed signals as seismic information for later retrieval as explained above. The crossline units 104 are each coupled, either in parallel or in series with one of the units 104a serving as an interface with between the central controller 106 and all crossline units 104.
In a conventional cable system data are relayed from one sensor unit to the next sensor unit and through field boxes hundreds of times before reaching the central recording system. Failure of any one field box or cable causes recording to stop until the fault is repaired due to the potential for losing large amounts of information. Consequently, common cable systems have an average uptime of about only 45%.
The basic architecture and reliability issues of the current cable approach described above prevent seismic data acquisition systems from being scaled to significantly higher channel counts. More recent cable systems incorporate different levels of redundancy to address the issue of single-point failure. These redundant systems include multiple redundant backbones, telemetry reversal and other redundancy features. These solutions, however, require even more cable to be deployed on the ground and still limit fault tolerance to no more than two failures in a line that can be many miles long.
Optimal spacing between seismic sensors varies depending on desired image depth and type. When deploying sensors obstacles are often encountered, such as no permit areas, rivers, and roads that cause the seismic crew to use varying spacing between sensor stations. Varying the distance between sensors in a conventional cable system is not convenient due to the fixed interval between connection points. Usually a surveying crew is used to locate the planned position of sensors on the ground prior to laying out the acquisition equipment. A backpack global positioning system (“GPS”) receiver is then is used by the surveyor and stakes are planted in the ground at each of thousands of predetermined sensor locations. Therefore, array deployment in the typical system is a two-step process adding time and labor costs to the seismic survey process.
In view of the typical seismic data acquisition system described above, there is a need for flexible spacing intervals between sensor units that will enable easy sharing of equipment between different crews without the worry of incompatible cables due to station interval requirements or to a particular environmental application (e.g., arctic, transition zone, and desert all require different types of cable).
There is also a need for integrating global positioning system (GPS) technology at the sensor unit to eliminate multiple crew process steps for identifying sensor locations and deploying sensors at the location. The typical system suffers, because the sensor unit is not co-located at the data acquisition device, thus the true sensor location is not available to the system for survey analysis.